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The use of hydrochloric acid (HCl) in gas well stimulation of high temperature reservoirs is currently facing different challenges. These challenges include rapid corrosion of the well tubulars, face dissolution, very high and uncontrolled reaction rate, and formation damage in high clay content and iron-rich reservoirs. In this study, water-soluble diethylene triamine penta acetic acid (DTPA) chelating agent is introduced as alternative to eliminate the risk associated with HCl at high temperatures. In addition, the potential of using seawater to replace fresh water in the stimulation process is explored to save the cost of fresh water transportation to deep offshore oil and gas wells. The effect of seawater on the reaction kinetics of DTPA with carbonate rocks under high pressure and high temperature conditions is investigated using the rotating disk apparatus. The reactions of DTPA solution diluted with fresh water (DTPA/DI) and seawater (DTPA/SW) with carbonate rocks were carried out at the same conditions. In the case of fresh water, the reaction is controlled by the surface reaction regime. Adding HCl to adjust DTPA pH did not turn the reaction into a mass transfer controlled reaction like the case of using HCl alone. The heavy matrix of seawater increased the resistance of ions diffusion, which resulted in a low reaction rate and transformed the reaction into a mass transfer limited regime. Corrosion tests were carried out on production and coiled tubing coupons obtained from the gas wells and the results of the new DTPA/SW formulation is compared to the standard HCl formulation. DTPA showed very low corrosion rate of 0.0034 g/cm2 without adding corrosion inhibitors compared to 0.205 g/cm2 of 15 wt% HCl with 3% corrosion inhibitors while the industry limit is 0.0244 g/cm2 in 6 h. The reaction regime of DTPA chelating agent with calcite is identified to be mass transfer limited in seawater and surface reaction limited in fresh water. The rate expression for the dissolution of Ca2+ in DTPA/SW solution is obtained. Coreflooding experiments were performed to determine the optimum injection rate using low permeability Indiana limestone core samples. The optimum injection rate required to stimulate a very deep carbonate gas well was found to be 1.4 bbl/min after scaling up the coreflooding results to field scale. The application of the new DTPA/SW formulation in treating deep gas wells is expected to save the cost of fresh water and eliminate the cost of corrosion inhibitors. ? 2017 Elsevier B.V.